Blowouts can occur when a column of mud in a wellbore weighs less than the formation pressure. More specifically, pressure within the wellbore will drastically increase when a formation expels hydrocarbon. The pressure increase sends a pressure wave up the wellbore to the surface that can damage the equipment that maintains the pressure within the wellbore. Besides the pressure wave, the hydrocarbons will travel up the wellbore because they are less dense than the mud. If hydrocarbons reach the surface and exit the wellbore through the pressure control stack (described below) before any of the components thereof are closed, there is a high probability that the drilling or production equipment will ignite the hydrocarbons. The resultant explosion or fire is dangerous and often deadly. To minimize blowout risk, drilling rigs must employ a plurality of different pressure control devices commonly referred to as a “pressure control stack,” comprised of an annular pressure control device, also known as a Blowout Preventer (“BOP”), a pipe ram pressure control device, and a blind ram pressure control device. If a “closed loop drilling” method is used, a rotating pressure control device (also known as a Rotating Control Device) will be added on top of the conventional pressure control stack. Those of ordinary skill in the art know of other types of pressure control devices. The various pressure control devices are positioned on top of one another, with any other necessary surface connections, such as the choke and kill lines for managed pressure drilling applications and nitrogen injection lines for under-balanced drilling applications. One of skill in the art will appreciate that elimination of one or more pressure control devices in the stack would reduce the overall height thereof, which will provide smaller drilling rigs.
Again, one of the devices in the pressure control stack can be a rotating pressure control device, also referred to as a rotating pressure control head. The rotating pressure control head is located at the top of the pressure control stack and is part of the pressure boundary between the wellbore pressure and atmospheric pressure. The rotating pressure control head creates the pressure boundary by employing a ring-shaped (i.e., a torus) rubber or urethane sealing element that engages and squeezes against the drill pipe, tubing, casing, or other cylindrical members (hereinafter, “drill pipe”). The sealing element allows the drill pipe to be inserted into (i.e., stabbed) and removed from the wellbore while maintaining the pressure differential between wellbore pressure and atmospheric pressure. The sealing element may be shaped such that the wellbore pressure causes a portion of the sealing element to engage the drill pipe. However, some rotating pressure control heads utilizes a mechanism, typically energized with hydraulic fluid, to apply pressure to the outside of the sealing element which forces the inner portions of the sealing element against the drill pipe. The additional pressure applied to the sealing element allows the rotating pressure control head to be used for higher wellbore pressures. The sealing element is firmly engaged onto the rotating drill pipe and rotates with the drill pipe. Thus, outer portions of the sealing element are associated with several bearings and rotating seals that allow the sealing element to rotate.
The sealing element will eventually wear out because of friction caused by drill pipe rotation, reciprocation, and vibration. Additionally, the passage of pipe joints, down hole tools, and drill bits through the rotating pressure control head causes the sealing element to expand and contract repeatedly, which also causes sealing element wear. Other factors may also cause sealing element wear, such as extreme temperatures, dirt and debris, and rough handling. Sealing elements thus require frequent replacement. If a worn sealing element is not replaced, it may rupture, causing a loss of hydraulic fluids and control over the well head pressure.
Currently, visual inspections or time based life span estimates are used to determine when to replace a worn sealing element. Visual inspections are subjective, and may be unreliable. Time based estimates may not consider actual operating conditions. More specifically, if the time based estimate is too conservative, sealing elements are replaced too frequently, causing unnecessary expense and delay. If the time based estimate is too aggressive, the risk for rupture may be unacceptable. Typically, sealing elements are replaced daily at a significant cost as the time to replace the element is substantial.
U.S. Pat. No. 7,380,590 (“the '590 patent”) discloses a Rotating Pressure Control Head (“RPCH”) having a sealing element fixed in an inner housing where the inner housing is rotatably engaged to an outer housing by an upper bearing and a lower bearing. The RPCH of the '590 patent offers many improvements over the prior art including a shorter stack size, a quick release mechanism for inner housing and sealing element change out, and a reduction in harmonic vibrations. However, wellbore fluid pressure, pressurized hydraulic fluid, and pipe friction against the sealing element exert a net upward or downward force on the inner housing that translates into a load on the upper and lower bearings. The need of bearings to accommodate sealing element rotation adds complexity and expense to rotating pressure control heads. In addition, one or more seals are required to maintain operating pressure and to prevent fluid escape. As one of skill the art will appreciate, these components also increase system complexity and cost.
Those of skill in the art will appreciate that a drill pipe contained within the pressure control stack may bend or otherwise move, wherein the drill pipe will not be located in the center of the pressure control stack, the ideal location. For example, the weight of the drill pipe may cause it to bow or deflect within the pressure control stack. In addition, during offshore drilling operations, wave motion will cause a floating platform to move relative to the ocean floor, which can cause the drill pipe to move within the pressure control stack. Even if the platform is fixed, ocean currents and surges can move the drill casing, which can move the drill pipe. Movement of the drill pipe in the radial direction and away from the center of the pressure control stack may reduce the life of conventional rotating pressure control devices or annulars. For example, a misaligned drill pipe will contact the surfaces of the sealing member unevenly, thereby increasing wear in some areas. In addition, the drill pipe may move away from the sealing element or cause the sealing element to deflect in such a way to create a gap between the drill pipe and the sealing element, which can cause drilling fluid to expel from the pressure control stack.
Another drawback of existing pressure control stack is that it is difficult to interface with a static flowline. More specifically, pressure control stacks include a stack outlet that interconnects to a rigid flowline that receives downhole pressurized fluid. It is often difficult to mate the pressure control stack to the flowline as these components are rarely in the ideal location or alignment. Thus, mating is usually a labor-intensive process wherein plumbers and welders must modify the flowline to make the connection with the pressure control stack. Movement of the pressure control stack, which may be caused by external forces described above, will stress the connection between the pressure control stack outlet and the flowline. One of skill the art will also appreciate that when the pressure control stack, or components thereof, are replaced, the connection between the outlet and the flowline must be broken and reconnected. If a new outlet is not exactly where the old outlet was relocated, additional modifications will be needed.
It is a long felt need to provide a pressure control device that reduces system complexity and costs. The following disclosure describes a passive sealing element that does not require bearings, rotary seals, and the need to apply pressure to a sealing element.